The press release issued by Tuktu Resources Ltd. (锟絋uktu锟� or the 锟紺ompany锟�) dated January 7, 2026 (the 锟絇ress Release锟�), in our opinion, is further evidence of the lack of understanding by the Tuktu Board of Directors (the 锟紹oard锟�) and current management regarding the development of the assets of the Company and exploratory plays such as the upper Banff.
Tuktu锟絪 current management is proposing to allocate the Company锟絪 available capital to try and develop the identified reservoir. We believe this is a mistake. The current management team and the Board have missed the key aspect of this play: it is mainly a fracture-controlled play, and these fractures developed about regional faults and folds have tapped into a world-class source rock. In our view, built from an intimate knowledge of the Company锟絪 assets and years of work exploiting fracture-controlled plays, the real prize is drilling natural fractures. We believe strongly that if the Company continues along their proposed path, it will lead to failure.
Specific criticisms of the Press Release are listed below.
锟�2D seismic review/interpretation upon completion will aid in our broader understanding of the play trap and trend system锟�29dk2902l
We disagree: 2D seismic review/interpretation will provide a regional context to the upper Banff Formation and will not likely result in an improved understanding of the reservoir. This is because the reservoir is very thin, discontinuous, and it has low seismic reflectivity. Further, seismic modeling and reprocessing efforts by previous management and consultants suggests that the reservoir is beyond seismic resolution.
Acquiring available 3D seismic
We disagree: Available 3D trade seismic in the general area is of lower resolution than the high-quality 2D lines previously purchased by the Company. A synthetic 2D reflectivity model was constructed, and it indicated that the likelihood of imaging the target sand in the current high quality 2D data was very low or unlikely. Additionally, the vertical discovery well is at the edge, and outside, of the available 3D trade data, thus the zone is not imaged adequately. As such, at the time of drilling, we concluded that a purchase of additional 3D data would not improve the Company锟絪 understanding of the intended drill location offsetting the vertical discovery well and only deplete our limited capital. The high-quality 2D lines, however, were reprocessed then depth converted to aid in well execution; one line was at the heel of the wellbore, the other at the toe; however, downhole geophysical tools were key to positioning the wellbore in the correct stratigraphic interval.
Statement that former Management Drilled out of Reservoir
We disagree: The horizontal well has been consistently referred to as 锟絛rilled out of reservoir锟� by the Company, but this is simply not the case. The horizontal well was drilled into the target zone, but it was found that the reservoir became less porous, less permeable, and more 锟絪haley锟� as we drilled away from the vertical well. Initial reservoir intersection during drilling operations featured a very thin reservoir sand, much thinner than the offset vertical well, only 350 m away. As such, the well was geosteered downward to intersect a potentially lower reservoir interval, but unfortunately none were encountered. By doing so, we were able to understand non-reservoir and reservoir cuttings and gamma ray character, which were then used for positioning of the remaining horizontal wellbore. The reservoir quality decreased away from the heel but the presence of siltstone and characteristic gamma ray signature with oil and gas shows confirmed the wellbore was within the correct reservoir interval. As part of the geosteering effort, an at-bit azimuthal gamma ray tool was used, which yields 10 cm-scale bedding attitude information. This is orders of magnitude better than associated seismic resolution. These downhole tools are key for directional drilling horizontal wells in highly complex reservoirs. In addition, approximately 300 tons of sand was placed through 20 ports in 100s of meters of intersected reservoir, and despite this effort, the well produced poorly. Later pressure transient information confirmed that the reason for low production was the presence of exceedingly low rock permeability. This is in marked contrast to the vertical well, only 350 m away, with only a 1 m of 7-9% porosity; this well is one of the best vertical oil producers in the basin in a number of years. The contribution of natural fractures to production was underestimated prior to the 16-20 well result. Also, reservoir quality was assumed to by more regionally continuous and more of a contributing factor to oil flow, but this has been contradicted by the horizontal well result. This is the nature of exploratory play development and new pool discoveries.
Current management and the Board appear not to recognize key reservoir components
The natural fracture component of this play is being vastly understated by current management and should be a concern to Tuktu shareholders (锟絊hareholders锟�). To call this a 锟絧orous play锟� that requires further understanding of stratigraphic architecture of the Banff Formation increases risk to future production results if the natural fracture system is not being considered. This is something that was learned from the horizontal well and the vertical offset discovery well. Production for the vertical well is unquestionably related to natural fractures. The simplest way to understand this would be to attempt to find another vertical well in the basin that maintained 400 barrels of oil per day and produced more than 100,000 barrels of oil in less than a year. This type of well capability does not exist in the absence of natural fractures. For it to be argued otherwise removes a key component to unlocking play value and places further risk on the return of capital. Additional evidence for the presence of a natural fracture system is that load fluid from the horizontal well stimulation operations was present in the vertical discovery production fluids. Fluid communication does not occur through matrix porosity alone and it is difficult to call a 锟絝rac hit锟� when reviewing the frac port placement of the horizontal well and present day in-situ stress profile. This direct communication also showed depletion at the heel of the horizontal well, adding another risk to the play: overcapitalization can occur without properly designed well spacing in context to the natural fracture system. Frankly, we believe that current management of the Company does not fully understand the nature of the play and that the activities proposed will not benefit Shareholders.
Gas and oil shows suggest drilling out of zone
Historical drilling in the Monarch area uses gas detection-while-drilling to aid in predicting productive reservoir, but in the recent horizontal drill, gas shows were muted. The relation between gas shows and reservoir production capability is not that simple. There are number of wells producing from the Lower Banff and Big Valley formations in the area that show very little gas response but produced significant volumes of oil. Drilling mud weight factors into the measured gas response and as such, gas can be a positive indicator. During the drilling of the lateral, drilling mud retorts indicated up to 5% formation oil in the water-based drilling mud, confirming the wellbore was in the appropriate zone, which is supported by cuttings and azimuthal gamma ray signatures.
On the divestment of assets
We disagree: Divestment of non-core gas assets will remove optionality for Tuktu during times of low oil prices and actually increase overall risk to Shareholders. The stable, long life, low decline gas assets in the foothills are required to provide an additional revenue stream to the Company and significant gas drilling upside under a favourable price forecast. Divestment of these assets increases further investor risk as it creates a company with only one asset.
Reduction in Asset Retirement Obligations (锟紸RO锟�)
Reduction of corporate ARO is not a new strategy. The previous management team deferred ARO, but was compliant under the strict provincial regulations, and deployed available capital into subsurface operations that could yield production, cash flow and strengthened share price. ARO maintenance is a corporate normal course regulatory requirement that, in most circumstances, adds questionable shareholder value.
In closing and under the direction of the newly elected board of directors, former management is committed to advancing the development of the lower Banff and Big Valley Formations. These formations are recognized as de-risked, proven oil-producing, fracture-enhanced reservoirs within the region. The exploitation of these assets will facilitate comprehensive data collection on the Upper Banff play, including the gathering of reservoir cuttings, core samples, and Formation Microimager (FMI) data.
We believe the Company under our proposed operations is strategically positioned to navigate periods of price volatility. By maintaining high net-back gas assets with substantial optionality and significant drilling upside, the Company should be able to allocate capital in alignment with anticipated price forecasts. We believe this approach ensures operational flexibility and resilience in fluctuating market conditions, a benefit to ongoing operations and Shareholders.
A central component of this strategy is the importance of natural fractures within each play. Fractures are critical to unlocking reservoir potential and optimizing production. The Company锟絪 asset portfolio has been carefully assembled to leverage the previous management team锟絪 specialized expertise in identifying, targeting and developing fracture-controlled plays. We believe this foundation supports the introduction of new, high-growth opportunities within the basin, further strengthening the Company锟絪 position and value creation potential.